The Role of Fireside Corrosion on Boiler Tube Failures, Part I

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One of the primary challenges of reliably burning coal is managing the corrosion experienced by the furnace heat transfer

surfaces. Fireside corrosion remains a leading cause of failure in superheater and reheater tubes. Also, tubes affected by the

fireside corrosion mechanism may lose 15 mils per year (mpy) and more in extreme cases. Five case studies (three

presented here in Part 1) examine the different failure modes experienced by tubes located throughout the furnace.

Fireside corrosion in the superheaters and reheaters of coal-fired units is known as coal ash corrosion, in oil-fired units as oil

ash corrosion, and in refuse-fired boilers as ash corrosion. Sometimes, fireside corrosion is also referred to as hot corrosion.

The mechanism in each case is similar, but the low-melting species in each is different. In coal ash corrosion, the low-melting

species would be sodium or potassium iron trisulphates (Na3Fe(SO4)3 or K3Fe(SO4)3); in oil ash corrosion they would be

V2O5-Na2O or V2O5-Na2SO4; and in refuse-fired boilers they would be chlorides of iron and zinc along with other possibilities

[see references 1 and 2 in the sidebar]. High temperatures (above 1,000F) of the superheater/reheater favor the formation of

these low-melting compounds.

The corrosion rate in coal ash corrosion, between 1,100F and 1,250F, is very high. In this temperature range, Na2SO4/K2SO4

reacts with surface oxides in the presence of SO3 to form complex liquid sulfates (Na3Fe(SO4)3 or K3Fe(SO4)3) that result in

rapid corrosion [3, 4]. Above 1,250F the corrosion rate is decreased significantly due to decomposition of these complex

liquid trisulfates. Once the liquid phase has been removed, the corrosion is due to oxidation in contact with flue gas.

The corrosion constituents in oil ash corrosion are vanadium, sodium, potassium, and sulfur. The combustion of fuel oil may

produce low-melting species V2O5-Na2O, V2O5-K2O, V2O5-Na2SO4, and V2O5-K2SO4. The melting points of these

compounds range between 1,000F and 1,550F, depending on composition [4, 5, 6]. The oil ash corrosion mechanism is

similar to coal ash corrosion: a low-melting-point liquid forms and it dissolves the protective iron oxides.

In refuse-fired boilers, chloride and sulfate species lead to the formation of low-melting- point liquids on the tube surface that

may contain iron, zinc, lead, and sodium. These species dissolve the protective iron oxide and expose the bare steel to the

corrosive environment, resulting in significant wall loss [7]. Reducing conditions inside the furnace may lead to the formation

of iron sulfide instead of iron oxide. The presence of carbon and iron sulfide within the ash deposits indicates the presence of

reducing conditions. Hydrogen chloride can more easily attack iron sulfides, rather than oxides, to form iron chloride as a

corrosion product. This iron chloride has a relatively low boiling point, and therefore iron chloride vapors form in the

superheater/reheater temperature range, and the corrosion mechanism is by loss of iron as a vapor. The porous sulfide

formed in reducing conditions allows easier formation and removal of iron chloride vapor.

Furnace wall tubes are also subject to fireside corrosion, but the low-melting species differ from superheater/reheaters.

Sodium and potassium pyrosulfate (Na2S2O7 or K2S2O7) have been responsible for furnace wall corrosion [1]. Both of these

species melt below 800F, where the furnace wall tubes operate. The melting points of Na2S2O7 and K2S2O7 are 750F and570F, respectively [4, 8, 9]. Mixtures of these two compounds could melt at even lower temperature. Melting points as low as

635F to 770F have been measured.

One finishing superheater tube sample, from a coal-fired unit, was received for metallurgical analysis. The tube was specified

as 1.875-inch outer diameter (OD) x 0.330-inch medium wall tubing (MWT), SA-213 T22 Cr-Mo steel. It had been in service

for 23 years. Figure 1 illustrates the as-received tube sample and the inner diameter (ID) view. Significant wall thinning was

observed on the flanks of the tube, characteristic of coal ash corrosion. Very hard scale was observed on the tube OD. On

Role of Fireside Corrosion on Boiler Tube Failures, Part I http://www.coalpowermag.com/print/ops_and_maintenance/The-

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the steam side, there was a thick oxide.

1. As-received tube and view of ID. Courtesy: David N. French Metallurgists

The tube sample was cross-sectioned, mounted, polished, and etched for metallographic examination. A 3% nital etchant

(100 ml ethanol and 3 ml HNO3) was used to reveal the existing microstructure. Metallographic examinations were

conducted via optical microscopy. Figure 2 shows thick scales at the tube OD and ID. A thick ID scale can raise the tube wall

operating temperature significantly. Figure 3 is a view of coal ash corrosion that had occurred on the OD.


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2. Cross-section of the tube wall facing the gas flow at 4.5x magnification. (Note that numbers on the images do not

necessarily correspond to the numbering in this article.) Courtesy: David N. French Metallurgists

3. View of coal ash corrosion at 100x magnification. Courtesy: David N. French Metallurgists

As shown in Figure 4, the microstructure of the T22 tube had transformed to ferrite with spheroidized carbides.

Metallographic examination was also performed at the 8:00 orientation of the tube to look for creep damage, if any. The

microstructure was the same, irrespective of the specimen location, and there was no evidence of creep.

4. Ferrite with spheroidized carbides, mid-wall at 400x magnification. Courtesy: David N. French Metallurgists

Tube wastage will often be evident and manifested as flat spots on either sides of the upstream of flue gas flow, as can be

seen in Figure 5a. A ring sample, Figure 5b, was sectioned from the tube for dimensional and hardness measurements

(Table 1). The tube had thinned significantly at the 4:00 and 8:00 positions due to coal ash corrosion. The thinnest section of

the ring (0.291 inch at the 8:00 position) was at 88% of MWT. The hardness, averaging 73 Rockwell B (RB), showed that the

tube had softened after 23 years of service.


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5a.

5b.

5. (a) Schematic representation of fireside corrosion. (b) Sectioned ring from the tube with corroded areas noted. The dark

spots are the locations of hardness measurements. Courtesy: David N. French Metallurgists


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Table 1. Case 1 dimensional and hardness measurements. Source: David N. French Metallurgists

Alkali oxides react with SO3 in the furnace atmosphere to form alkali sulfates (K2SO4 or Na2SO4) on the oxide scale. Some of

the SO3 diffuses through the alkali sulfates, and reaction occurs at the oxide-sulfate interface to form alkali-iron-trisulfates

(K3Fe(SO4)3 or Na3Fe(SO4)3) according to the following two chemical reactions:

In this process, the thickness of the oxide scale decreases and the metal oxidizes further to renew the oxide layer. The tube

metal temperature decreases as slag thickens. At room temperature, low-melting compounds sinter the ash particles to form

a tightly bound inner layer. After the slag thickness reaches equilibrium, deslagging increases because the liquid layer on the

tube cannot support a thick layer of ash. This deslagging increases the tube-metal temperature. This process (slagging and

deslagging) repeats in a cycle that leads to create the corrosion pattern known as "elephant hiding" or "alligator hiding."

Coal ash corrosion of the tube analyzed in Case 1 resulted in significant wall loss. The temperature range for formation of

trisulfates is between 1,000F and 1,250F. The decomposition of trisulfates occurs when the temperature exceeds 1,250F.

Above this temperature, coal ash corrosion reduces significantly. Numerous empirical equations have been proposed for

estimating the tube operating temperature based on the oxide scale thickness in superheaters and reheaters. Using one of

these equation with the measured ID scale thickness (25 mils) and hours of operation (171,300 hours) results in an

estimated tube temperature of 1,100F [11]. This estimated tube temperature was within the susceptible temperature range fo

trisulfate formation and coal ash corrosion. The metallography confirmed that the tube had operated in this temperature

range. The tube microstructure had transformed to ferrite with completely dispersed carbides, and the hardness had

decreased.

Log X = 0.00022 (T+460) (20+Log(t)) -7.25

Where:

X = steam-side scale thickness in mils

T = absolute temperature (F+460), and

t = time in hours

A high-temperature vertical reheater tube was received for failure analysis. The tube was specified as 2.25-inch OD x

0.180-inch MWT, SA-213 TP-304H stainless steel. It had been in service for 15 years. The fuel type was No. 6 Bunker C oil.

Figure 6 is the as-received tube with specimen locations illustrated, including a close-up view at the failure site and the ID

view. Significant wall thinning was observed at the failure.


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6. As-received tube with specimen locations illustrated, close-up of failure, and the ID view. Courtesy: David N. French

Metallurgists

Figure 7 is a specimen at Location F1 with fracture face on the left. The tube is darker in the outer one-third of its cross-

section due to carburization. Intergranular corrosion (Figure 8) occurred along the grain boundaries due to chromium

depletion. The depletion of chromium content due to carbide formation along the austenite grain boundaries and within the

surface grains reduces the corrosion resistance of stainless steel. Within and below the carburized layer, the intergranular

cracking is typical of creep. Higher stresses due to significant wall loss at the failure contributed to intergranular creep cracks

The tube wall was thinned down to approximately 0.075 inch at the edge of the failure. There was no evidence of plastic

deformation at the fracture face, which is typical for creep failure.

7. Location F1, oxalic at 4.5x magnification. Courtesy: David N. French Metallurgists


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8. Location F1, fracture face at 42x magnification. Courtesy: David N. French Metallurgists

Location F2 also had intergranular cracks with some of the grains missing at the tube OD due to pull-out during polishing

(Figure 9). In Figure 10, the microstructure shows sensitized austenitic grains with large carbides along the grain boundaries.

Sensitization occurs from 800F to 1,500F, with the most rapid sensitization at 1,200F.

9. Location F2, intergranular cracks along the grain boundaries at the OD at 200x magnification. Courtesy: David N. French

Metallurgists


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10. Location F2, sensitized grains, mid-wall at 400x magnification. Courtesy: David N. French Metallurgists

Similar carbides were observed in the mid-wall away from the failure at Location B (Figure 11). Although sensitization

decreases the corrosion resistance, it does not affect the mechanical properties significantly.

11. Location B, sensitized grains, mid-wall, 12:00 at 400x magnification. Courtesy: David N. French Metallurgists

Ring samples (Figure 12) were sectioned from the tube for dimensional and hardness measurements. The tube had thinned

significantly: Ring A is 72% of MWT at the 2:00 position, and Ring B is 48% of MWT at the 12:00 position. The hardness,

averaging 83 Rockwell B (RB), is slightly above the range for new SA-213 TP304H, 72-81 RB, as expected for material that


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has been carburized.

12. Sectioned rings. Courtesy: David N. French Metallurgists

Elemental analysis was performed on white deposit that was scraped from the OD surface. Analysis was via energy

dispersive spectroscopy in the scanning electron microscope (see ASTM E1508-98) [10]. The carbon and sulfur content was

determined by combustion analysis (ASTM E1019-03) [11]. The results are summarized in Table 2. The deposit was primarily

iron oxide. Chromium, nickel, and manganese were likely from the steel. High amounts of carbon and sulfur indicate the

possibility of reducing conditions. Unburnt carbon due to reducing conditions resulted in carburization of stainless steel tube.

Potassium, sodium, and vanadium in the deposit point to the presence of low-melting species (such as V2O5-Na2O,

V2O5-K2O, V2O5-Na2SO4, and V2O5-K2SO4) which may have contributed for significant wall loss. Calcium and phosphorus,

from water or water treatment chemicals, were formed after the tube failure. Minor amounts of arsenic, magnesium, titanium,

and chlorine were also detected. The white color may be associated with aluminum and silicon in the deposit.


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Table 2. Constituents of the whitish reheater tube OD deposit. Source: David N. French Metallurgists

The reheater tube failed due to oil ash corrosion, resulting in thinning and creep. Reducing conditions caused carburization of

stainless steel. The microstructure had transformed to carbides along the austenitic grains. Carburization and sensitization

contributed to a reduction in corrosion resistance that resulted in significant wall loss. The OD deposits also point to thepresence of low-melting compounds that caused oil ash corrosion.

A secondary superheater tube was received for metallurgical characterization. The tube was specified as 2.125-inch OD x

0.420-inch MWT, SA-213 T22 Cr-Mo steel. It had been in service for 43 years. Figure 13 illustrates the as-received tube with

specimen locations, and the tube ID view. The oxide scale is seen at the ID. Some roughening and pitting corrosion were

observed on the OD.


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13. As-received tube with specimen locations illustrated and the ID view. Courtesy: David N. French Metallurgists

Figure 14 is the close-up view of pitting corrosion that had occurred on the OD. A specimen was circumferentially cross-

sectioned to determine the depth of pits. Figure 15 is the close-up view of alligator hiding due to oil ash corrosion. Alongitudinally cross-sectioned specimen was examined to determine the significance of oil ash corrosion at Location B.

14. Close-up view of pitting corrosion at Location A at 3:00. Courtesy: David N. French Metallurgists

The pits observed in Figure 14 were shallow, and there was some intergranular attack along the grain boundaries, as shown

in Figure 16. The alligator hiding (circumferential ridges) shown in Figure 15 was measured, and the deepest oil ash

corrosion was 15 mils from the OD (Figure 17). The cycling of metal temperature causes ash layers to form and shed,


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leading to the alligator hiding. These circumferential grooves from the tube OD are typical for fireside corrosion. No creep

damage was seen at the OD or at the tip of the groove. This area of the tube was exposed to the highest temperature,

making it more likely to have oil ash corrosion.

15. Close-up view of alligator hiding at Location B at 1:00. Courtesy: David N. French Metallurgists

16. Location A, 3:00, superficial pit, OD at 100x magnification. Courtesy: David N. French Metallurgists


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17. Location B, 1:00, 15 mils depth of ash corrosion, OD at 100x magnification. Courtesy: David N. French Metallurgists

The microstructure had transformed to ferrite with spheroidized carbides due to years of service (Figure 18). Similar

microstructure was observed irrespective of the specimen location.

18. Ferrite with spheroidized carbides, Location B, 12:00, mid-wall at 400x magnification. Courtesy: David N. French

Metallurgists

The thickest scale was measured as 20 mils (Figure 19). Based on the oxide thickness and years of service, the tube

temperature was estimated as 1,064F. This temperature is below the recommended maximum for T22 material, 1,075F, but

43 years ago the maximum temperature may have been 1,125F. The operating temperature was within the susceptible


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temperature range for formation of low-melting-point constituents in oil ash corrosion, 1,000F to 1,500F. The low-melting

compounds in oil ash corrosion are V2O5-Na2O, V2O5-K2O, V2O5-Na2SO4, and V2O5-K2SO4. Unlike coal ash corrosion, these

compounds do not thermally decompose at higher temperature.

19. Location B, 6:00, ID with 20 mils of scale at 100x magnification. Courtesy: David N. French Metallurgists

Superficial pitting and some alligator hiding were observed on the OD of the superheater tube due to oil ash corrosion.

V2O5-Na2O, V2O5-K2O, V2O5-Na2SO4, V2O5-K2SO4, or reducing conditions inside the furnace may have contributed to

alligator hiding in this superheater tube. The tube microstructure had transformed to ferrite with spheroidized carbides after

43 years of service.

In Part II we'll explore several more case studies, including ash corrosion of a superheater and fireside corrosion of a water

wall tube.

1. David N. French, Metallurgical Failures in Fossil Fired Boilers, 2nd ed., John Wiley & Sons Inc.

2. R.C. Corey, H.A. Grabowski, and B.J. Gross, "External Corrosion of Furnace-Wall Tubes III," Transactions of the

ASME, vol. 71 (November 1949), pp. 951-963.

3. R.B. Dooley and W.P. McNaughton, Boiler Tube Failures: Theory and Practice, EPRI, vol. 3, ch. 33, "Steam

Touched Tubes" (1996).

4. W.T. Reid, External Corrosion and Deposits: Boilers and Gas Turbines(New York: American Elsevier Publishing

Co., 1971).

5. J.O. Collins and W.A. Herbst, "How Ash of Residual Fuel Oil Affects High Temperature Boiler Operation," POWER,

vol. 98 (November 1954), pp. 100-101.

6. H.W. Nilson, A Review of Available Information on Corrosion and Deposits in Coal and Oil-Fired Boilers and Gas

Turbines, Battelle Memorial Institute, 1958.


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7. A.J.B. Cutler, W.D. Halstead, J.W. Laxton, and C.G. Stevens, "The Role of Chloride in the Corrosion Caused by

Flue Gases and their Deposits," Transactions of the ASME(July 1971), pp. 307-312.

8. R.W. Bryers, "Prospects of Fireside Ash Deposition While Firing Coal/Oil Mixture," Joint Power Generation

Conference, St. Louis, Missouri (October 1981).

9. P.D. Miller, C.J. Slunder, H.H. Krause, and F.W. Fink, State-of-the-Art Report on Control of Corrosion and Deposits

in Stationary Boilers Burning Residual Fuel Oil, Battelle Memorial Institute for Bureau of Yards and Docks, Navy

Department (May 1963), Accession Number: AD0422073.

10. ASTM Standard E1508 - 98, "Standard Guide for Quantitative Analysis by Energy-Dispersive Spectroscopy,"ASTM.

11. ASTM Standard E1019 - 03, "Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen

in Steel and in Iron, Nickel, and Cobalt Alloys," ASTM.

-Dr. Rama S. Koripelli ([email protected]) is metallurgical engineer, Dr. David C. Crowe

([email protected]) is technical director, Dr. David N. French is founder, and Jonathan Brand

([email protected]) is a senior metallurgical technician for David N. French Metallurgists.

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The Role of Fireside Corrosion on Boiler Tube Failures, Part I